Federal Energy Regulatory Commission

To encourage billions of dollars of investment into America’s transmission grid over the next several decades, the Federal Energy Regulatory Commission (FERC) is restructuring its regulatory policies to bring market-based solutions into the framework for planning, construction, and operation of new transmission lines. The recent Order 1000 is the most dramatic example of this effort. But as FERC has learned before, one set of rules doesn’t serve the financial and commercial needs of all market participants.

With a flurry of major new environmental regulations, the Environmental Protection Agency (EPA) is altering the power generation landscape. But will the new federal rules survive court challenges—to say nothing of next year’s national elections? Fortnightly's Michael T. Burr considers the controversy over new environmental standards. PLUS: Top Utility Lawyers of 2011.

Six years after Congress granted FERC “backstop” siting authority for electric transmission projects in the Energy Policy Act of 2005, the regulatory landscape is still evolving as a result of federal court decisions and new FERC orders. But despite a lack of certainty at the federal level, project sponsors have filed numerous applications at the state level for new transmission projects. Can these projects proceed without greater certainty at FERC?

1. ‘Policy’ Guides the Grid; 2. Carbon Not a Nuisance (Yet); 3. Gigabucks for Negawatts; 4. A MOPR, Not a NOPR; 5. Ramp Up the Frequency; 6. Cap-and-Trade Still Lives; 7. Cyber Insecurity; 8. Korridor Killer; 9. The Burden Not Shared; 10. Ozone Can Wait.

Adopting an interoperable framework for the smart grid isn’t just a question of technology standardization. It’s also about navigating the legal, regulatory, and business factors that affect technology implementation. Making the smart grid work will require utilities and regulators to assert leadership.

Federal and state regulators play a critical role in the evolution of the smart grid. Lawmakers face a host of questions, from deciding who owns consumer data and how it can be used, to defining a new range of regulated and unregulated utility services and applications. How much regulation will be needed to manage the transformation to a smart grid? And how much regulation will be too much?

When customers sell demand response into a regional capacity market (such as PJM’s Reliability Pricing Model, known as the RPM), how much credit should they earn for agreeing to curtail demand and alleviating stress on the grid — that is, for reducing the market’s need for generating capability and capacity reserve margin? And further, should the amount of credit depend on whether the customer works with market aggregators, known both as CSPs (“Curtailment Service Providers”) or ARCs (“Aggregators of Retail Customers”)? One view would pay customers for the full extent of their curtailment of demand — known as its “Guaranteed Load Drop” (GLD). The other would limit capacity credit to the customer’s prior load history — “Peak Load Contribution,” or PLC. The answer may well dictate whether regulators continue to treat “energy” and “capacity” as two distinct concepts.

Many utilities have trimmed their capital spending in the face of economic weakness and regulatory uncertainty. At the same time, strong energy sales have boosted cash flow and profits. Backed by regulated returns and clear resource plans, the industry should step up infrastructure investments. Are we ready to lead America out of economic malaise?

When a capital-intensive industry enters an asset-building cycle, many companies will operate in the red for a few years or more. That’s not necessarily a bad thing, as cap-ex investments represent growth for shareholders. The devil is in the details, however, and companies facing a large slug of environmental compliance investments might produce disappointing returns over the next few years.